The selection of materials for well construction is essential to the successful completion of an oil or gas well. Among the most important is the selection of a drilling fluid. A drilling fluid having the desired properties is passed down through the drill pipe, out a nozzle at the drill bit, and returned to the surface through an annular portion of the well bore. The drilling fluid primarily functions to remove cuttings from the bore hole; lubricate, cool and clean the drill bit; reduce friction between the drilling string and the sides of the bore hole; maintain stability of the bore hole; prevent the inflow of fluids from permeable rock formations; and provide information on down hole conditions. The composition of a drilling fluid is carefully selected to optimize production within the vast diversity of geological formations and environmental conditions encountered in oil and gas recovery. At the same time, the fluid should not present a risk to personnel, drilling equipment, or the environment.
In most rotary drilling procedures the drilling fluid takes the form of a “mud,” i.e., a liquid having solids suspended therein. The solids function to impart desired rheological properties to the drilling fluid and also to increase the density thereof in order to provide a suitable hydrostatic pressure at the bottom of the well. The drilling mud may be either a water-based mud or an oil-based mud.
Water-based drilling muds may consist of polymers, biopolymers, clays and organic colloids added to a water-based fluid to obtain the required viscous and filtration properties. Heavy minerals, such as barite or calcium carbonate, may be added to increase density. Solids from the formation are incorporated into the mud and often become dispersed in the mud as a consequence of drilling. Further, drilling muds may contain one or more natural and/or synthetic polymeric additives, including polymeric additives that increase the rheological properties (e.g., plastic viscosity, yield point value, gel strength) of the drilling mud, and polymeric thinners and flocculents.
Polymeric additives included in the drilling fluid may act as fluid loss control agents. Fluid loss control agents, such as starch, prevent the loss of fluid to the surrounding formation by reducing the permeability of filter cakes formed on the newly exposed rock surface. In addition, polymeric additives are employed to impart sufficient carrying capacity and thixotropy to the mud to enable the mud to transport the cuttings up to the surface and to prevent the cuttings from settling out of the mud when circulation is interrupted.
Most of the polymeric additives employed in drilling mud are resistant to biodegration, extending the utility of the additives for the useful life of the mud. Specific examples of biodegradation resistant polymeric additives employed include biopolymers, such as xanthans (xanthan gum) and scleroglucan; various acrylic based polymers, such as polyacrylamides and other acrylamide based polymers; and cellulose derivatives, such as dialkylcarboxymethylcellulose, hydroxyethylcellulose and the sodium salt of carboxy-methylcellulose, chemically modified starches, guar gum, phosphomannans, scleroglucans, glucans, and dextrane. See U.S. Pat. No. 5,165,477, which is incorporated herein by reference.
Most drilling fluids are designed to form a thin, low-permeability filter cake to seal permeable formations penetrated by the bit. This is essential to prevent both the loss of fluids to the formation and the influx of fluids that may be present in the formation. Filter cakes often comprise bridging particles, cuttings created by the drilling process, polymeric additives, and precipitates. A key feature of a drilling fluid is to retain these solid and semi-solid particles as a stable suspension, free of significant settling over the time scale of drilling operations.
The permeability of the filter cake is dependent upon particle distribution, particle size, compressive forces, and electrochemical conditions of the mud. The composition of the drilling fluid may be adjusted to increase or decrease permeability, for example, by adding soluble salts, increasing the number of particles in the colloidal size range, and/or to vary their surface charge. Fluid from the mud which permeates the barrier is known as filtrate. The probability of successful completion of a well may depend, in large part, upon the filtration properties of the mud being matched to the geological formations and the composition of the filtrate.
Filtration occurs as the suspended particles slurried in the drilling fluid are trapped against the wellbore wall. So long as the hydraulic pressure on the drilling fluid is greater than the geomechanically derived pressure on the fluids within the formation, the difference in pressure will drive drilling fluid to flow into the formation. The solid particles in the slurry are drawn along by the hydrodynamic drag produced by the fluid moving into the formation. At the wellbore wall, if the particles are large enough to bridge the openings in the formation, the particles are stopped. The particles are then held by the drag of the fluid (filtrate) flowing around them and into the formation openings.
Because the openings between the bridging particles are generally smaller than the initial openings, finer particles are now able to bridge, and thus be removed from the fluid stream. The increasing buildup of solids correspondingly reduces the flow of filtrate, so the hydrodynamic force that propels and traps particles in the filter cake is continually reduced. Conversely, hydraulic pressure on the drilling fluid, since it may no longer force fluid to flow, is increasingly expressed as mechanical pressure across the depth of the filter cake. This mechanical pressure works to pack and compress the initially formed particle bed into denser and less permeable arrangements. Generally speaking, the greater the differential pressure, the higher the ultimate mechanical pressure with concomitantly greater compression of the layers of filter cake first laid down. Greater compression results in tighter particle packing, higher mechanical strength, and lower permeability.
This process may cause the drill string to become ‘differentially stuck’ in a wellbore. When sufficient filtration flux is present to draw the impermeable pipe against the wall, its blockage of flow is quickly translated into mechanical force, holding it in place. Pipe stuck in this fashion should be quickly freed, or the forces may become too great for the draw works at the surface to pull it free. If not quickly freed, the forces may exceed the tensile strength of the pipe so that it is impossible to free it by pulling from the surface.
When the fluid is not being actively pumped though the well, the process continues, trapping smaller and smaller particles, until the fluid flux through the ever deeper bed becomes too slow to move particles. Eventually, the permeability is reduced to a point where even though some finite volume of filtrate may continue to pass, its drag is insufficient to overcome the forces that maintain the particles in suspension, resulting in succeeding layers of particles building up very little mechanical compression. Generally speaking, while more viscous than the initial fluid, this layer of relatively widely separated particles is softer and more permeable than the compressed filter cake below. At this point, the ‘filter cake’ is really a dewatered suspension, sometimes called ‘dehydrated mud’ in the case of water-based fluids.
When the fluid is actively pumped, the flow of fluid along the axis of the wellbore is much faster than the radial flow of fluid into the formation. The axial flow along the wellbore now creates drag to pull particles up the wellbore and away from the formation pore where filtration is occurring. As may be expected, the filter cakes formed by a circulating fluid are more permeable than those formed under static conditions. Such cakes are referred to as ‘dynamic’ cakes to differentiate them from those formed under static conditions. It has been estimated that up to 80% of all the filtrate lost to formation is lost through dynamic filtration with circulating fluid.
Fluid flow up the wellbore is typically fastest around the drill bit and the several stands of larger diameter, heavy-weight drilling collars, pipes, down hole motors, jars, etc. immediately above it. Such drill collars and heavyweight pipe are larger in exterior diameter, while having the same interior diameter as the pipe above, and they possess more mass and provide extra ‘weight,’ or pressure on the drill bit, to improve its rate of penetration. Their increased stiffness may also serve to reduce excursion of the drilled hole from the planned trajectory. Motors, turning the bit independent of the pipe, are also often larger in diameter than the body of pipe above.
Somewhat paradoxically, this region of fastest flow is also the region that most needs filter cake. This is the area that has most recently been exposed to the drilling fluid. The freshly drilled rock has had the shortest time to build up any sort of filter cake, and the higher fluid velocity more actively strips away the growing particle bed than at any other point in the well. Not surprisingly, it is during the time between drilling and the formation of an equilibrium dynamic cake that most of the filtrate is lost, with potentially damaging results. This is often the region where pipe becomes differentially stuck.
Because much of modern drilling is done with sequential, discrete pieces of pipe, circulation is periodically interrupted to allow a new piece of pipe to be inserted into the closed circulation path. These momentarily static conditions result in rapid filter cake growth. Resumption of circulation strips much of this newly formed cake away, but especially in the near-bit region, some of the statically placed particles remain to improve the dynamic cake.
There are a number of chemical ways of adjusting filter cake properties are known in the art, including the use of clay and non-clay based drilling fluids, use of weighting materials, viscosifiers, dispersants, fluid loss control agents, insoluble reinforcing materials, breaking fluids, and encapsulated delivery particles.
Specifically, U.S. Pat. No. 4,506,734, incorporated herein by reference, provides a method for reducing the viscosity and the resulting residue of a water-based or oil-based fluid introduced into subterranean formation by introducing a viscosity-reducing chemical contained within hollow or porous, crushable and fragile beads along with a fluid, such as a hydraulic fracturing fluid, under pressure into the subterranean formation. When the fracturing fluid passes or leaks off into the formation, or the fluid is removed by back flowing, the resulting fractures in the subterranean formation close and crush the beads. The crushing of the beads then releases the viscosity-reducing chemical into the fluid. This process is dependent upon the closure pressure of the formation to obtain release of the breaker and is, thus, subject to varying results dependent upon the formation and its closure rate.
Further, U.S. Pat. No. 4,741,401, incorporated herein by reference, discloses a method for breaking a fracturing fluid comprised of injecting into the subterranean formation a capsule comprising an enclosure member containing the breaker. The enclosure member is sufficiently permeable to at least one fluid existing in the subterranean environment or injected with the capsule such that the enclosure member is capable of rupturing upon sufficient exposure to the fluid, thereby releasing the breaker. The patent teaches that the breaker is released from the capsule by pressure generated within the enclosure member due solely to the fluid penetrating into the capsule whereby the increased pressure caused the capsule to rupture (i.e., destroys the integrity of the enclosure member), thus releasing the breaker. This method for release of the breaker would result in the release of substantially the total amount of breaker contained in the capsule at one particular point in time.
U.S. Pat. No. 4,919,209, incorporated herein by reference, discloses a proposed method for breaking a fracturing fluid. Specifically, the patent discloses a method for breaking a gelled oil fracturing fluid for treating a subterranean formation which comprises injecting into the formation a breaker capsule comprising an enclosure member enveloping a breaker. The enclosure member is sufficiently permeable to at least one fluid existing in the formation or in the gelled oil fracturing fluid injected with the breaker capsule, such that the enclosure member is capable of dissolving or eroding off upon sufficient exposure to the fluid, thereby releasing the breaker.
However, encapsulated delivery particles, and methods of triggering payload delivery, as described in the prior art, have limitations. For example, premature release of the enzyme payload sometimes occurs due to product manufacturing defects, imperfections, or coating damage experienced in pumping the particles through surface equipment tubular and perforations. Additionally, premature release of the enzyme payload may cause damage to drilling components and the formation being drilled due to the acidic and/or caustic properties of the encapsulated payloads. As such, a localized application of a filter cake adjusting particle and/or enzyme may be beneficial to the successful completion of a well.
The probability of successful completion of a well, and the cost of drilling a wellbore is proportional to the time it takes to drill to a particular location and depth. In oil and gas drilling the time it takes to remove the drillstring from the wellbore, known in the field as “tripping,” can greatly increase the cost of drilling a well. When a low quality filer cake is formed, the time it takes to trip the drillstring may increase due to problems such as differential sticking. Differential sticking occurs when a drillstring is held against the filter cake by hydrostatic pressure in the wellbore, most commonly during the pulling of a drillstring from the wellbore, or as a result of filter cake accumulation on a drill bit.
Methods and apparatuses for promoting filter cake sealing are known in the art. One example of such a method is disclosed in SU 1361304 A1, therein describing a device deployed by centrifugal action, and relying on such centrifugal action to apply a sealing pressure to the filter cake. Alternate examples of methods and apparatuses are disclosed in WO 2004/057151 A1, therein describing providing a sliding mechanical contact to a filter cake. The sliding mechanical contact provides a small angle of attack from extendable subparts to provide a plastering effect to the filter cake.
While the above mentioned methods and apparatuses may provide mechanical contact with a filter cake, there still is a need for methods and apparatuses for providing an optimized filter cake that may decrease the costs associated with tripping the drillstring, reducing downtime, and thereby increasing overall drilling efficiency. Additionally, there exists a need for methods and apparatuses that may provide for simultaneous application of chemicals or energies that improve the sealing and strengthening character of a filter cake, thereby further improving drilling efficiency.